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Report: Unlocking the Economic Potential of North America's Energy Resources

A report published by analysts at Goldman Sachs, released as part of their North American Energy Summit event held June 10-11, 2014. The report says the clock is ticking and time is limited for North America to take advantage of the shale oil and gas boom currently under way. And what, pray tell, is holding us back? Certainly not capital (i.e. money) for drilling. Rather, it is money for what the report's authors say is on the "demand response" side of the equation.

2.
The authors would like to thank David Tamberrino, Vikas Sharma, Felipe Mattar, Theodore
Durbin, Brian Maguire, Damien Courvalin and Christian Lelong for their significant contributions
to this paper.
The Global Markets Institute is the public-policy research unit of Goldman Sachs Global
Investment Research, designed to help improve public understanding of capital markets and their
role in driving economic growth.

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June 2, 2014 Global Markets Institute
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Executive Summary
The “demand response” phase of the shale revolution is stalling
Last year North America spent nearly $200 billion on producing oil and gas, attracting over
50% of global upstream investment, outspending Russia and Saudi Arabia combined by an
astonishing factor of 10-to-1. However, as supply-side investment surges ahead, demand-
side investment lags.
Although North America has access to some of the lowest energy prices in the world,
reinvestment rates in energy-intensive manufacturing that create high-value jobs lag those
of Asia and the Middle East, by a more impressive 15-to-1. Further, the region has also
fallen short in building the infrastructure to ensure the benefits of abundant energy
supplies can be fully reaped. As temperatures plunged this past winter, gas could not be
delivered where it was needed, creating regional price spikes.
If these trends continue, North America will not only fail to harness the benefits from the
shale revolution it created, but it will also forego over the next decade more than 2 million
new jobs, 1.0 % of additional GDP growth and at least a 5% incremental reduction in
greenhouse-gas emissions.
The window of opportunity for North America to benefit fully from its potential is limited.
While North America can easily point to the economic advantages generated by shale,
these advantages were based on legacy infrastructure rather than resource availability.
Many other countries have similar resources as North America, particularly China. They
only lack the infrastructure needed to unlock these resources. This means that it is only a
question of time before other nations catch up with North America.
Time is of the essence to act now, so what can be done to turn this resource wealth into
real economic value?
Opportunity to pursue shared environmental and economic goals
All of these problems share a common solution: stable and well-defined energy,
environmental and transportation policies. While the “shale revolution” has taken place
without an energy policy, we note that this involves short-term, quick-turnaround
investments. In contrast, the demand-side investments that we need today are larger in
scale, requiring decades to recoup the investment, and as such require a high level of
confidence in future policies.
Creating policy aimed at establishing such long-term confidence has real economic
benefits and is an opportunity for business and government to work together to support
the shared goal of a clean environment, a strong economy and sustainable job creation
that has historically defined North America.
We therefore see three key policy themes on which business and government can work
together to create the conditions necessary for this much-needed investment: (1) reducing
uncertainty through effective regulations, (2) optimizing costs and emissions across the
entire value chain and (3) focusing on scalability and diversification of technologies.
1. Reduce uncertainty through durable and effective regulations
The long-term nature of energy-intensive demand-side investments underscores the need
for stable, not temporary, rules that create an economic vision of the future. To make multi-
billion dollar demand-side investments that require decades to generate an adequate rate

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June 2, 2014 Global Markets Institute
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of return, investors need to be confident in the future for fracking in that it can be done
safely within well-defined and well-understood rules.
In order to be predictable, regulation needs to be clear, uniform and effective. In our view,
effective energy policy should be conducted in terms of both protecting the environment
and in attracting longer-term responsible investment. These objectives are not mutually
exclusive.
2. Optimize costs and emissions along the value chain
To optimize emissions and costs, emission limits should be approached from the
perspective of “well-to-wheel” rather than simply focusing on certain downstream
segments such as automobiles or power generation. For instance, unless the energy
source meaningfully shifts to renewable energy, the headline emissions benefits of a “zero-
emissions” auto industry are overstated when accounting for the entire well-to-wheel
supply chain. We estimate that if methane emissions at the well-head and pipeline were
contained, gas-based fuels could deliver transportation with lower total emissions than
gasoline at lower investment costs than the “zero-emissions” automotive technologies,
and these trade-offs therefore need to be carefully addressed.
Specifically, we believe that natural gas-based ethanol and electric vehicles are the two
most promising alternatives to gasoline based upon cost, potential emission reductions
and consumer payback. However, natural gas-based ethanol and electric vehicles have
very divergent investment requirements: ethanol is very front-end-loaded at the upstream
drilling and refining stage with little burden on the consumer, whereas electric vehicles
require comparatively less infrastructure investment but a much larger investment borne
by the consumer, and a high level of uncertainty remains around battery costs.
3. Focus on scalability and diversification of technologies
Renewable energy is cleaner and more sustainable, but currently there are real challenges,
such as intermittency (the sun is not always shining, nor the wind blowing), that currently
limit their ability to reliably supply North America’s power needs. Through improving cost
structures and technologies, as well as various incentives and mandates, renewables are
set to continue to take market share. However, until centralized electricity storage
technology options emerge and become scalable, technologically driven limits on
scalability exist for renewables – making other technology options necessary as base-load
resources.
Cost and environmental concerns may drive a lower reliance on nuclear or coal generation,
impacting their scalability, making increasing use of natural gas a necessity as more of a
base-load resource, especially given significant scalability advantages. While policy should
help facilitate R&D in new technologies, it should also ensure that it does not crowd out
investment of known scalable technologies, which have the potential to lower emissions.
But predicting technological advances remains challenging, which is why we recommend a
diversified portfolio approach to power generation with an emphasis on natural gas until a
new clean, low-cost, scalable technology emerges.
Five questions that need answers to kick-start the demand phase of the revolution
We believe that to create an environment more conducive to investment to achieve these
goals, five questions need to be addressed before kick-starting the demand response phase
of the shale revolution: (1) What are the best fracking practices and water rules? (2) How
can pipeline rules and regulations be improved? (3) What are optimal strategies for
capturing fugitive methane? (4) How can natural gas-based ethanol (E85) fueled and
electric vehicles be encouraged in the transportation sector? and (5) What reforms in the
power generation sector should be instituted?

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Overview: Unlocking the economic potential of North America’s
energy resources
In policy circles, investment forums and public commentaries today, it has become an
almost common refrain to cite the energy revolution that is occurring in the United States
and, more broadly, in North America. The economic potential from this revolution is, no
doubt, tremendous and has major implications for the US and global economies. But, the
United States will never fully realize the benefits from the energy opportunity and create
the new jobs needed if it does not have a demonstrable and coherent energy and
environmental policy that creates the right conditions for a longer-term approach to
investment and infrastructure.
The economic benefits of getting shale right could be considerable
Under a favorable policy mix we estimate that shale technology has the potential to boost
North American economic activity, create jobs and reduce emissions considerably over the
next decade. We estimate that aggressive policy reform has the potential to increase
economic growth by 0.9 percentage points per year in the United States and create 1
million jobs over the next decade. Similarly, we see the opportunity for Mexican GDP
growth to benefit by 1 to 1.5 percentage points per year over the next decade, creating
more than 1 million jobs. And we estimate Canadian growth could be boosted by 0.25%
per year over the same time horizon. At the same time, the shift towards cleaner burning
fuels in both power generation and transportation combined with methane capture has the
potential to reduce emissions in the United States alone by at least 5% by 2025.
Exhibit 1: The economic potential from investing in gas demand is considerable
GS estimated incremental GDP (in percentage point, lhs) and cumulative employment impact
(thous, rhs) in “max. potential” gas demand scenario
Source: Goldman Sachs Global Investment Research.
0
200
400
600
800
1,000
1,200
-
0.20
0.40
0.60
0.80
1.00
1.20
2014 2018 2022 2026 2030 2034 2038 2042 2046 2050
Cumulative employment impact Incremental GDP effect

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The “demand response” phase of the shale revolution is stalling
But the future of shale will ultimately depend on how energy and environmental policy can
adapt to the changing technology. To date, most analysis has focused on the positives for
North America of the shale revolution. On the other hand, far less attention has been paid
to the economic opportunities North America has failed to harness from the revolution.
Instead, the United States seems more on track to export shale, as the United States has
lagged other countries in generating the demand – and the high-value manufacturing jobs
that come along with this demand – needed to consume shale gas. In this respect, we
believe that the shale revolution may stall and not see the full longevity of the “demand
response” phase.
Exhibit 2: US ethylene additions have been consistently
lower than both the Middle East and Asia…
Ethylene capacity additions, in thousand tonnes
Exhibit 3: … despite its favorable position on the cost
curve, especially relative to Asia
Ethylene breakeven costs by region/feedstock (2013), in US
$/tonne
Source: IHS. Source: IHS.
The United States and North America more broadly have access to some of the lowest
natural gas prices in the world. But reinvestment rates in the energy-intensive
manufacturing that create high-value jobs lag those of Asia and the Middle East. For
example, both of these regions have outspent the United States by a remarkable 15-to-1 on
new ethylene expansions over the last four years (see Exhibits 2 and 3). Despite the fact
that US natural gas can be transformed into motor fuels for as little as $1.60 per gallon
equivalent – and with lower well-to-wheel emissions than gasoline – very little investment
has gone towards creating gas-based transportation demand in the United States.
Exhibit 4: US investment in upstream energy has been strong relative to peers
Global energy production in volume and value, and capex (2013)
Source: BP statistical review, Spears & Associates, China Ministry of Land and Resources, Haver Analytics, Goldman Sachs
Global Investment Research.
-4,000
-2,000
0
2,000
4,000
6,000
8,000
10,000
12,000
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
North America Middle East Asia
0
200
400
600
800
1000
1200
1400
Middle East
Ethane
US Ethane China (Coal
based)
SEA Naphtha US Naphtha EU Naphtha NEA Naphtha
Country (kb/d) (bcf) (mln mt) (Bn. US$) (Bn. US$)
US 11,722 24,326 823 $825 $152
Russia 10,877 23,580 199 $730 $12
Saudi Arabia 11,306 3,860 0 $495 $9
China 4,212 4,268 3,054 $476 $50
Canada 4,008 5,493 26 $227 $23
*Using Brent price for Liquids, Europe price for Natural gas and Australia price for coal
Drilling CapexTotal Liquids Natural Gas Thermal Coal Market Value*

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As demand lags, supply is surging ahead. Last year the United States spent $152 billion on
producing oil and gas, attracting nearly 50% of global investment, and outspent Russia by
an equal factor of 15-to-1 (see Exhibit 4). Demand simply cannot keep pace with supply –
and this is why exports are the focus of policy choices today. To keep the value of shale at
home, and to reap its economic benefits here rather than abroad, significant investment is
needed on the demand side (see Exhibit 5).
Exhibit 5: While upstream energy investment is now outperforming US average, the
downstream sector continues its long-term underperformance
Capital investment index, 1984=100
Source: Haver Analytics, Goldman Sachs Global Investment Research.
Uncertainty lies behind this failure to harness the shale revolution
Several factors underlie disappointing demand-side investment. These include a lack of
confidence in the future economics of these projects, a lengthy and uncertain permitting
process, regulations that cannot keep pace with today’s technologies and substantial
uncertainty around the long-term viability of shale gas. All of these problems share a
common solution: stable and well-defined environmental, energy and transportation
policies. It is true that the “shale revolution” has taken place without a matching energy
policy, but shale has been a relatively quick-turnaround investment. In contrast, the
demand-side investments needed today are larger in scale, requiring decades to recoup the
investment and a high level of confidence in future policies.
Although there exists substantial economic potential in creating demand for energy from
the transportation, industrial and residential sectors, very little has been done today to
harness this potential. Heating costs this winter showed how the United States has fallen
short in reaping the benefits of the abundant gas it has already produced. As temperatures
plunged, gas could not be delivered where it was needed. The result was natural gas prices
in large metro regions in the northeast above $120/mmBtu, even as prices stood at just
$4/mmBtu elsewhere across much of the United States. Insufficient investment in pipeline
and distribution infrastructure lay behind this severe dislocation in prices.
0
50
100
150
200
250
300
350
400
1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
US Private Downstream Energy Upstream Energy

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Even though natural gas prices in the United States are 60% to 75% lower than in Asia and
Europe, energy-intensive manufacturing has failed to rise significantly or to create much-
needed jobs. Since the onset of the shale revolution in late 2010, key energy-intensive
manufacturing sectors such as chemicals and petroleum products have underperformed
the broader economy by 2.2% p.a. and have generated only 5,000 new jobs, compared to
40,000 jobs if these industries had grown in line with US manufacturing more generally
(see Exhibit 6).
Today’s policies do not embrace the new fuel options generated from new technologies;
they constrain the use of methanol and natural gas-based ethanol made from natural gas
in the fuel stream, despite lower costs and potentially lower emissions. At the same time,
long-term investment decisions–which are for our long-term economic benefit–require a
higher degree of clarity on our national LNG and oil export posture. This would reduce
uncertainty around future pricing and availability of cheap energy.
Exhibit 6: While headline IP has recovered post-crisis, energy-intensive sectors have not
performed so well
Industrial Production Index, seasonally adjusted (2007 = 100)
Source: Haver Analytics.
Moreover, the inability to use abundant shale resources is beginning to derail the shale
revolution on the supply side as well, which has been a bright spot for the US economy.
The shale revolution created an estimated 175,000 new jobs in oil and gas extraction and
services and boosted industrial production growth by one-third since 2010. In fact, today
natural gas production is already completely constrained by a lack of demand. This can be
seen in the substantial slowdown in natural gas production growth rates after 2011 (see
Exhibit 7).
70
75
80
85
90
95
100
105
110
2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
Total index Chemicals

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Exhibit 7: Supply growth has recently been weighed down by demand constraints
US dry gas production 12 month moving average, in Bcf/d
Source: EIA
Policy can address these issues to unlock the potential
As we laid out above, the opportunity for the North American economy to profit from
increased capacity to consume the shale resources it is producing is considerable. To take
advantage of this opportunity, policy needs to solidify confidence in the next 30 years that
is required to attract the capital. The key in unlocking the potential on the demand side is to
attract the capital. For example, if we were to invest $1.2 trillion dollars today in gas-based
automotive technologies the United States could consistently reduce its energy bills by as
much as 10% by 2035.
However, the reality of the shale revolution is that there is ample supply potential of
hydrocarbon fuels that is economic at current prices. As a result, running out of
hydrocarbon fuels is not going to force the economics of renewables, creating an
even more difficult task ahead in reducing emissions. This further increases the need for
well thought out environmental and energy policy.
Further, the window for North America to benefit fully from its potential is limited. While
North America can easily point to the economic advantages generated by shale, these
advantages were based on legacy infrastructure rather than resource availability. Many
other countries have similar resources as North America, particularly China. They only lack
the infrastructure needed to unlock these resources. This means that it is only a question of
time before other nations catch up with North America and it could be a matter of years
rather than decades.
All of these factors underscore the need for timely cooperation among business leaders,
investors and policymakers. Indeed, in the next section (pages 25-29), we describe the key
policy questions we think need to be addressed in the near term to kick-start a
sustained demand response phase of the shale revolution : (1) What are the best
fracking practices and water rules? (2) How can pipeline rules and regulations be
improved? (3) What are optimal strategies for capturing fugitive methane? (4) How can
40
45
50
55
60
65
70
1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014
Production growth has slowed
considerably since mid 2012 as
insufficient demand growth has been
a constraint.

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June 2, 2014 Global Markets Institute
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natural gas-based ethanol (E85) fueled and electric vehicles be encouraged in the
transportation sector? and (5) What reforms in the power generation sector should be
instituted?
These are the “low hanging fruit” that we believe could set policy on the path to
encouraging long term confidence in the ability of the energy sector to deliver its potential
across North America.
We then go on to investigate in detail three key policy themes we believe should remain in
focus in the longer term where business and government can work together to unlock the
full potential of shale: (1) reducing future uncertainty around resource availability, (2)
optimizing costs and emissions across the entire supply chain and (3) focusing on
scalability of technologies in both transportation and power generation. In so doing, we
offer a vision for how such policy reforms could shape the outlook for transportation,
industrial and power generation sectors.
Finally, from page 57, we estimate the economic benefits that could be gained from this
policy environment in two separate case studies, for the United States and Mexico
respectively.
On page 74, we include a Glossary which defines the terms we use throughout the paper.
For the remainder of this overview, we now explain why we believe these three themes are
of core importance to conducting effective energy policy in North America and how
addressing them can generate a significant economic boost to the North American
economy.
1. Policy should aim to reduce uncertainty and create stability and
credibility
To create an economic vision of the future, an effective environmental and energy policy
needs to be defined strictly enough by addressing all the 5 key questions that we outline in
the policy question section such that future government changes do not lead to future
policy change, including interpretation of enforcement.
Since the onset of the shale revolution, the North American energy market has failed to
fully capture the economic benefits of shale. This is most apparent in the energy-intensive
manufacturing sectors, where industrial output has notably underperformed the broader
manufacturing recovery (recall Exhibit 6).
Driving this underperformance has been a lack of investment in large-scale, capital-
intensive projects required to transform energy into growth, including the failure to invest
in the pipeline and distribution mechanisms needed for the energy to reach its consumers.
As we noted earlier, uncertainty driven delays have underpinned these failures. We believe
the following issues in the market have contributed to the high level of uncertainty at the
energy demand level:
1. Little confidence in the future price and availability of energy supplies, as many
consumers are left with the painful memories of the 1990s when large-scale
investments were made only to have the viability completely lost during the early
2000s when North American energy prices spiked form the lowest in the world to the
highest in the world almost overnight, as the excess capacity driven by 1970s energy
policy was completely exhausted.
2. This lack of confidence is further exacerbated by the lack of policy addressing key
environmental and energy issues. The long-term, large-scale nature of these
demand-side investments requires rules and regulations that create an economic and
environmental vision of the future. This means that investors must be reassured that

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fracking can be done safely within well-defined and well-understood rules, and that
any labor shortages can be managed in the context of well-articulated immigration
policies, such that they believe they can recoup their investment over a long time
horizon. Further, a recognition that a renewables-focused generation mix will likely
require natural gas as an inexpensive complement to solve the intermittency problem
will be key.
The key is that policy needs to establish confidence in the sustainability of an
environmentally safe energy supply with confidence around its pricing, the availability of
labor and timely and efficient permitting that is matched to current technologies. Once the
uncertainty is diminished investors would likely be far more willing to commit capital to
long-term demand-side projects.
How uncertainty delays investment
Companies weigh two important issues when undertaking a large-scale investment:
1. Large-scale capital investments are mostly irreversible such that the company
cannot disinvest, making the investment a sunk cost, which also applies to labor due to
the costs associated with hiring, training and firing.
2. An investment decision can be delayed, which allows the company to gather new
information about input prices such as natural gas, the future regulatory environment
and other market conditions like the demand for the product they are considering
producing.
Most importantly, the investment behavior driven by these two characteristics is easily
shown to be extremely sensitive to the risks and uncertainty around factors such as energy
input prices or supply availability (see the textbox on Investment Delays Stemming from
Uncertainty). For example, in making the decision to build an energy-intensive
manufacturing plant, the risks around long-term natural gas prices, future supply
availability ten years from now and the regulatory landscape are far more important to the
investment decision than the consensus view of $4.25/mmBtu for long-term natural gas
prices.
The result is that the risks around these variables - from energy prices and supply
availability to interest rates and policy – rather than the actual values of these variables
create the investment problem. The implications of this are far-reaching for
policymakers, suggesting that they should be focused on demonstrating stability and
credibility in trying to stimulate investment, as this is more important than simple tax
breaks or other incentives that can change over time with governments.
The empirical evidence of delayed investment
Not only can we establish theoretically how uncertainty creates delays in investment, but
the empirical evidence in the energy-intensive manufacturing sectors also bares out this
conclusion. Despite extremely attractive economics, a large number of projects are still
currently being delayed, pushed out in time for a variety of reasons, including permitting,
land siting, labor availability, future gas prices and supply availability (see Exhibits 8-9).

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If we use the oil-to-gas spread as a measure of the value of the option to invest in gas-fired
manufacturing or generation capacity, then the value of this option rises with the level of
uncertainty around making such investments. This option had no value in 2007 when gas
was trading near parity with oil but it increased as the shale revolution took hold, creating
new investment options, but it has continued to rise as the investment environment has
remained difficult, going far past what would be considered optimal (see Exhibit 10).
Exhibit 10: The lack of demand response has come despite gas pricing cheaply relative to
oil after 2007
Cost of WTI oil relative to NYMEX natural gas front-month contracts, weekly average in
mmBtu/bbl
Source: ICE, NYMEX, Goldman Sachs Global Investment Research
The key issue here is that the supply-side investments do not suffer from these same
investment uncertainty issues because they are far more quick-turnaround investments –
shale energy is now a 12-month turnaround investment. In contrast, the demand-side
investments require far longer to recoup the capital outlay, which is why it is critical for
policy makers to create rules that are viewed both credibly and with confidence that they
will not change such that the investor becomes confident that they will recoup their
investment. This will likely require strict environmental regulations around fracking and
fugitive methane emissions that are unlikely to be reversed in the future by a new
government.
0
10
20
30
40
50
60
Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14
`Btu parity': at this level, oil
and gas are priced equally
on an energy equivlant
basis.

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Box 1: Investment delays stemming from uncertainty
We outline a simplified analysis showing how uncertainty over supply availability, characterized by fears of price
volatility, can delay the firm’s investment decision, even if a favorable, low-input cost environment is eventually
reached. We apply this analysis to the case of US natural gas and a fertilizer company that is considering investing in a
new factory. One of the key decisions the company must make is whether to invest today, while the regulatory
environment and future of shale is still uncertain, or to delay their investment and wait for greater certainty over supply
and prices of natural gas inputs.
Using the standard investment analysis technique of expected Net Present Value (NPV) we can demonstrate how the
expected profitability of the decision to invest today is lower than that of waiting a year and investing when price
certainty is greater. We make a number of simplifying assumptions in the outline analysis below, including a fixed price
of fertilizer output and a constant 10% discount rate. But these do not change the overall market conclusion: greater
input-price uncertainty is likely to lead to lower production volumes (at least in the short run), and higher prevailing final
product prices.
Exhibit A: A simple example of how input price uncertainty can delay a firm’s fixed investment decision
Payoffs from delayed investment decision versus price uncertainty – assumes a continuous price distribution
Source: Goldman Sachs Global Investment Research
As a stylized example with a binary price distribution, we assume that the price of US natural gas could take two paths:
 The first path would see gas prices declining to $4.00/mmBtu as shale technology continues to roll out and improve.
 The second path sees prices rising to $7.00/mmBtu with shale technology being scaled back.
Assuming a long-term average price of $5.50/mmBtu, we assign a probability of 50% to each outcome so that on
average, gas prices are not expected to trend up or down.
$5.50 $/mmBtu
Foregone profit
from delay.
Breakeven price,
$/mmBtu
Distribution of possible
gas prices, $/mmBtu
Price uncertainty favours investment delays,
giving the firm the option to avoid the capital
commitment should gas prices rise beyond
breakeven, capping downside risk.
Importantly, the firm still has the opportunity
to invest tomorrow should prices remain
attractive, allowing it to capture the upside.

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Cont’d Box 1: Investment Delays Stemming from Uncertainty
The expected NPV of investing today is:
50% of the NPV under a gas price increase + 50% of the NPV under a gas price decrease
The fixed cost of the investment is $1 billion. Operating profits are $250m per year in the low-cost environment and
$50m per year in the high-cost environment.
This gives an expected NPV of $500m for investing today:
Expected NPV from investing today = 50% Low-cost NPV + 50% High-cost NPV
$500m = 0.5*(-1000+2500) + 0.5*(-1000+500)
Under the same assumptions, if the fertilizer company delays investment until there is certainty over input prices then
the expected NPV will either become more positive (if gas prices fall) or fall below zero (if gas prices rise).
Because no company would invest in a project with a negative NPV, the expected NPV from waiting becomes:
Expected NPV from waiting = (50% probability of prices falling * Low-cost NPV + 50% probability of
prices rising * 0) * discount factor due to 1 year’s delay
$682m = 0.5*(-909 + 2273)
The expected NPV is just over $180m larger in the future, so the firm will rationally delay its investment decision. In fact,
the firm would actually be willing to pay up to $180m in order to secure this delay.
Increasing the range of prices, or the probability that we will end up in the high cost environment, increases the value of
waiting, all else equal.

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Box 2: Lift the uncertainty on the export ban rather than the ban itself
Although (for statutory reasons) the United States cannot export crude oil, surging domestic production has contributed
to stabilize global oil prices through weaker US crude imports and higher petroleum product exports. Specifically, with
US and global petroleum inventories stable over the past four years, the growth in US crude production has been
sufficiently large to meet global oil demand growth despite weak supply growth outside North America. Further, the
surge in shale oil production has likely also lowered the marginal cost of producing oil – and oil prices as a result –
given the compelling economics of this growing source of future production growth.
Nevertheless, the current discount of US crude oil prices relative to seaborne crude oil prices has not translated into
discounted domestic transportation fuel prices relative to the rest of the world because the United States continues to
import petroleum products. As a result, the benefits of the US shale revolution through lower transportation fuel prices
have been similar in the United States and abroad (absent currency and policy fluctuations as well as level of taxation).
The idiosyncratic benefits of the US shale revolution on the US economy have so far been concentrated in specific
sectors of the economy such as the refining sectors.
A clear commitment to keeping the export ban in place would stimulate downstream refinery capex investment to catch
up to the upstream investment, helping to absorb growing domestic light crude production. On the other hand, if the
export ban was lifted, US crude oil production would realize its strongest growth potential. However, with domestic
prices converging back to seaborne crude oil prices, the margin advantage of domestic refiners would diminish and
limit capex growth in the downstream sector. While export volumes would increase, the United States would be
exporting the “value added” of processing its shale oil along with these barrels.
However, uncertainty on whether the export ban will be lifted or not (the current status quo) means that both upstream
and downstream capex will ultimately suffer. Uncertainty is currently delaying any significant investment to open new
refineries to process domestically produced crude, while simultaneously depressing demand and prices for upstream
producers. This sub-optimal outcome features not only slowing domestic crude oil production but also limited growth
in the downstream processing capacity and ultimately offers the least benefit to the US economy.
Exhibit 11: Surging domestic crude production has
reduced the call of the US on the global oil market…
Thousand Barrels per Day
Exhibit 12: … however US transportation fuels have
remained indexed to global prices despite declining
domestic oil prices
$/bbl
Source: EIA. Source: EIA.
-4000
-2000
0
2000
4000
6000
8000
10000
12000
Crude oil production Crude oil net imports Petroleum product net exports
-12
-10
-8
-6
-4
-2
0
2
4
6
8
Domestic vs. seaborne crude oil price differential (LLS vs. Brent)

18.
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2. Policy should optimize across the vertical supply chain from
“well-to-wheel”
1. North America light vehicle transport landscape is an open field at historical
crossroads. We believe government policy as well as improvements in technical
capability will have a significant impact in determining the mix of powertrains over the
next few years;
2. We believe that natural gas-based ethanol and electric vehicles are the two most
promising alternatives to gasoline based upon cost, potential emission reductions,
consumer payback, and abundance of natural resources;
3. However, electric vehicles and natural gas based ethanol have very divergent
investment requirements: ethanol is very front end loaded at the upstream drilling and
refining stage with little burden on the consumer whereas electric vehicles require
comparatively less infrastructure investment but a much larger investment borne by
the consumer.
Part of resolving the demand-related uncertainty is to create confidence in what are best
and most efficient technologies and processes that reduce costs and emissions across the
entire supply chain. Emission limits should be approached from the perspective of “well-
to-wheel” rather than simply focusing on certain segments such as automobiles, power
generation or refining. This requires a focus on all aspects of the supply chain where the
total costs should be compared to the total emissions in evaluating competing
technologies.
Exhibit 13: Ethanol well to wheel CO2e emissions are similar to gasoline but could be materially improved by reducing
methane leakage….
Grams of Co2e per km
Source: Argonne National Laboratory, Goldman Sachs Global Investment Research.
For example, the headline emissions benefits of a “zero-emissions” auto industry are
overstated when accounting for emissions through the well-to-wheel supply chain. We
estimate that if methane emissions at the well-head and pipeline were contained, gas-
based fuels could deliver transportation with lower total emissions than gasoline with
Gasoline Diesel Ethanol Methanol
Compressed
Natural Gas
Hydrogen
fuel cell
Electric
Vehicle
Well Extraction 9 9 24 24 48 22 13
Refining/conversion/
generation
51 39 60 60 13 158 155
Transportation/pipeline NA NA NA NA NA NA NA
Retail distribution NA NA NA NA NA NA NA
Wheels Consumption 230 191 211 205 189 0 0
TOTAL 289 240 295 289 250 180 168
TOTAL adjusted for 3/4
reduction in CH4 leakage 289 240 266 260 233 180 168
CO2e grams per kilometer

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June 2, 2014 Global Markets Institute
Goldman Sachs Global Investment Research 18
lower investment requirements than the “zero-emissions” automotive technologies, and
these trade-offs therefore need to be carefully addressed (see Exhibits 13 and 14).
Exhibit 14: … at much lower all-in investment cost than the zero-emissions automotive technologies
Full lifecycle investment requirement for converting all 250mn light vehicles to various fuels, $bn
Source: Goldman Sachs Global Investment Research, company reports, EIA, NREI.
We believe the economic advantages of approaching environmental and energy policy
questions from the perspective of the entire supply chain are significant and can achieve
the following three benefits:
1. Cost and emissions control. Focusing on the entire vertical supply chain substantially
increases the ability to control both costs and emissions throughout the distributions
system by eliminating redundant, less-efficient and more-emitting steps, but most
importantly, it allows for optimal utilization of the natural resource and renewable
assets to avoid waste and reduce transportation costs.
2. Reduce volatility in prices and supply. Putting an emphasis on investments that
optimize the vertical supply chain also allows for greater resource input access and
optionality as opposed to simply being tied to one fuel type and or technology such as
multi-fuel fired generation capacity, which allows the industry to adapt more quickly to
changing market environments on both the supply and demand side.
3. Avoid irreversible investments. Energy technologies and infrastructure are extremely
capital intensive with very long lead times to implement; therefore, any investment
that turns out to not be of best use in the entire supply chain is extremely difficult to fix
and likely irreversible, particularly given the scale of transportation, making a mistake
is extremely costly.
From well-to-wheel or well-to-wall – many areas for improvement
Assessing and optimizing across the vertical supply chain clearly needs to begin with the
well or mine, including exploration where emissions are first released. It is important to
emphasize that these emissions, particularly methane, have real economic value if they can
safely be contained and marketed. This further reduces not only the emissions, but the cost
of the exploration and production of oil and gas. The Environmental Defense Group
recently estimated that the value of capturing these emissions is $110-$150 million dollars.
Gasoline Diesel Ethanol Methanol
Compressed
Natural Gas
Hydrogen
fuel cell
Electric
Vehicle
Well Extraction NA ‐$ 829$ 829$ 452$ 225$ 80$
Refining/conversion/
generation NA 363$ 1,281$ 768$ ‐$ 163$ 718$
Transportation/pipeline NA ‐$ 19$ 19$ 209$ 139$ 425$
Retail distribution NA 3$ 91$ 167$ 531$ 361$ 110$
Wheels Consumption NA 457$ 76$ 127$ 2,029$ 5,072$ 2,110$
TOTAL NA 823$ 2,296$ 1,910$ 3,221$ 5,961$ 3,443$
Incremental investment (billions)

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Transportation of oil and gas to processing facilities is another area where both costs and
emissions can be reduced. In gas the big issue is methane emissions. Here the problem is
related to the lack of defined property rights for the pipeline operators such that they have
no incentive to fix the leaks because they cannot take ownership of the gas they prevent
from escaping and therefore cannot monetize it to pay for the leaks; this is a result of
current federal policy.
In oil transportation, it is the difficult and lengthy process of getting pipelines approved and
built that is forcing oil to be transported via railroads. This is not only a more expensive
long-term transportation option, but it is also far more environmentally dangerous as
evidenced by recent accidents and associated spills. Clearly, pipelines are far more optimal
from both cost and environmental perspectives.
Processing is an area in which loss rates, emissions and costs can all be optimized. Natural
gas has a clear competitive edge on a cost basis to nearly all other technologies. Not only
are combined-cycle units far less costly than other technologies with relatively low
emissions, but they also retain a high level of optionality in that alternative fuels can be
processed to generate electricity in time of duress. Even on the transportation side –
conversion to methanol, natural gas-based ethanol and compressed natural gas are all
relatively low cost processing technologies on a capital cost basis.
Transmission is where the renewables join the vertical supply chain and where the value
of renewables needs to be assessed, as there is usually a significant tradeoff between zero
emissions and land usage (particularly is the case with biofuels). To overcome this land
constraint, wind and solar are typically built far from residential and urban areas which
then requires a significant investment in power line transmission that can create a new set
of environmental problems. These transmission issues combined with the fact that wind is
typically far more productive at night when demand is low requires delicate matching of
renewable capacity with demand to avoid redundancy that already exists with some wind
capacity.
As the supply chain moves to the end user, upfront capital costs and fuel optionality
become the critical issue in minimizing both costs and emissions. On the distribution side
there is a need for policy aimed at the coordination of infrastructure development and
allowing free fuel choice. With the new technologies come new fuel options such as natural
gas-based ethanol where the drivetrain technology already exists, so allowing for more
fuel choices would create more demand for natural gas in the transportation sector and
help create the confidence needed to build out the distribution infrastructure to deliver
natural gas into the transportation sector at prices far below gasoline.
Finally, it is important to emphasize that while we see both natural gas-based ethanol
electric vehicles as the superior technologies on a well-to-wheel basis (see Exhibit 15), the
two technologies have very divergent investment requirements: ethanol is very front–end-
loaded at the upstream drilling and refining stage with little burden on the consumer,
whereas electric vehicles require comparatively less infrastructure investment but a much
larger investment borne by the consumer. This last point reinforces the point that policy
choices in the transportation sector will have a critical impact on investment patterns and
ultimately which technology becomes more dominant.

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Exhibit 15: Natural gas-based ethanol (E85) and electric vehicles have the best
cost/emissions trade off relative to consumer payback time period
Well-to-wheel emissions against capital cost by fuel; bubble size represents years until
consumer can payback the excess vehicle cost relative to gasoline
Source: Argonne National Laboratory, EIA, NREI, company reports, Goldman Sachs Global Investment Research
3. Policy needs to promote scalability and diversification in
generation
1. Renewable generating capacity will continue to take market share as technologies
improve and as they benefit from policy-backed incentives/mandates, though many of
these incentives require a “socialization” of costs. Until centralized electricity storage
technology options emerge and become broadly available at volume, technologically-
driven limits on scalability exist for renewables (due to intermittency and climate
change), making other technology options necessary as base-load resources;
2. Cost and environmental concerns may drive a lower reliance on nuclear or coal
generation – impacting their scalability – making increasing use of natural gas a
necessity as more of a base-load resource, especially given significant scalability
advantages;
3. Predicting technological advances remains challenging and we recommend a
diversified portfolio approach to power generation – but emphasizing the importance
of natural gas generation as a source for base-load power and as capable of “solving”
intermittency issues created by expanding renewable generation portfolios.
The most important lesson that we learned over the last decade on the supply side is that
not all technologies are scalable and picking the right one is nearly impossible. Ten years
ago, oil sands, ultra deepwater, gas-to-liquids and shale were all promising technologies
with relatively low costs when done in small scale. However, as the industry scaled each of
these technologies up in size, it soon found that only one of them worked with truly large
scale – and that was shale (see Exhibit 16).
0
50
100
150
200
250
300
350
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000
WTWEmissions(CO2egrams)adj.formethaneleakage
Incremental Capital Cost ($bn)
Gasoline
Diesel
E85
Methanol
CNG
Hydrogen fuel cell
Electricity
E85 involves a relatively
balanced trade‐off
between capital costs and
reducing carbon
emissions.
Electricity is superior on
emissions reductions,
though capital costs are
sizeable, and borne largely
by the consumer.
Methanol challenged by
issues of toxicity.

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Exhibit 16: Of the competing new oil production technologies, only shale could be scaled
up without a dramatic increase in costs
Breakeven of non-producing and recently onstream oil assets by category, US$/bbl
Source: Goldman Sachs Global Investment Research
The reason for this was that the other technologies hit unforeseen geological and
technological constraints that prevented them from being scaled up at low cost. In contrast,
shale was initially considered the least likely technology as the costs were expected to be
too high on the oil side, but as it was scaled up on the natural gas side, engineers learned
how to reduce the costs substantially on the oil side, leading to the entirely unexpected
surge in US oil production.
This same uncertainty in technology also applies to the demand side as well, which is why
we emphasize the importance of considering the following issues in designing a successful
energy policy:
1. Scalability. This not only creates economies of scale to keep consumer costs low, but
with the right technologies it also allows for a meaningful reduction in emissions;
however, not all technologies are scalable but rather hit a scalable limit, most likely
technological that needs to be overcome by engineers, which in the meantime makes
other technologies more cost effective to be scaled up.
2. Diversification. However, because we do not know which technologies can be
ultimately scaled up (just as we did not know about shale), we should diversify our
investment across technologies until they hit their scalable limit while engineers either
find a solution or the technology is deemed ineffective.
3. Socialization. In some cases, a technology such as solar may provide significant
benefits to society through reduced emissions but given current technology may not
be economically viable such that socializing its costs through subsidies or tax breaks is
optimal; however, to the extent that government subsidies for adoption of the
technology exceed the cost of rapid adoption of competing technologies or the
opportunity cost of using research and development for new future technologies then
such subsidies need to be reassessed.
20
30
40
50
60
70
80
90
100
110
0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000
Breakeven(US$/bl)
Cumulative Peak Production (kbls/d)
Traditional
Heavy oil
Deepwater
"Shale
oil"
Ultra
deepwater

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In general, the economics of renewables and other new technologies work up to a scalable
limit, but because the scale limit is below the market for other technologies a greater
emphasis must be placed upon the truly scalable technologies given current technologies
such as natural gas, at least until the technological progress improves. Further, a truly
scalable technology can be done without creating negative externalities that generate costs
in other parts of the economy, i.e., biofuels turn a carbon problem into an arable land and
food problem when the process is scaled up.
Avoid picking a winner before the engineers do
In many cases scaling up a technology that hits a known constraint requires faith that
sometime in the future someone will find an adequate solution to take it to the next level.
While we remain positive that engineers will solve the battery problem for electric vehicles,
there still exists some uncertainty around the availability of lithium and other rare earth
metals. For example, 50% of potential lithium supply reserves are in Bolivia where very
little large-scale Lithium mining has been done, so the cost of this production is still
relatively unknown – it could turn out far cheaper or far more costly – as scale can change
everything. There is also the issue that reserves are even more concentrated than those for
oil, potentially creating geopolitical risks.
Nonetheless, many of the cutting-edge technologies that are carbon-free run into far more
serious constraints and most will remain niche markets until engineering solves their
scalability problem. For example, wind faces the problem that most of the output occurs at
night when demand is low such that large-scale battery technology will be required to truly
scale up the technology. Intermittency remains a key challenge impacting the scalability of
renewables – as these sources have much lower utilization rates than conventional forms
of power generation (see Exhibit 17). Unlike nuclear or coal generation, natural gas power
plants can ramp up quickly to respond to the potential for wind or solar generation to
decline rapidly, intra-day, as their respective resources decline. Accordingly, natural gas
generation has a key role to play in a well-diversified, sustainable generation mix.
Exhibit 17: With relatively high utilization rates and low capital costs, combine-cycle gas
plants offer significant scalability in the power sector
Capacity factors and $/kW capital costs by fuel type
*Size of the bubble represents relative generation levels on identical plant capacity
Source: EIA, Goldman Sachs Global Investment Research.
Gas-fired generation, due to its low capital or construction costs, emerges as one of the
most economic ways for the United States to meet significant increases in power demand –
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 1,000 2,000 3,000 4,000 5,000 6,000
Capacityfactor
$/kW capital cost
Gas-CCGT
Gas-Peaking
Nuclear
Wind
Solar

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on cost alone, assuming natural gas prices in the $4-$6/MMBtu range – even when
incorporating current benefits associated with other forms of power generation, such as
tax credits for renewables or government sponsored debt financing for new nuclear.
Utilization rates remain much higher for conventional generation sources such as gas fired
generation than for many other forms, while the $/kW installed construction costs will likely
remain lower at least for the near and medium term (see Exhibit 18).
Exhibit 18: At natural gas prices up to $6/MMBtu, new combined cycle plants appear
mostly economic versus other forms of new power generation capacity
Levelized cost of electricity ($/MWh) – scenario analysis at natural gas prices of $4 - $6/MMBtu
Source: Goldman Sachs Global Investment Research.
Nonetheless, the United States can meet increases in power demand driven by growth in
the electric vehicle fleet or by other drivers – including a major manufacturing renaissance
– through a variety of potential resources, including the development of new natural gas,
renewable, nuclear and coal generation capacity. Trade-offs clearly exist and
environmental impacts matter – likely limiting some potential options, such as a major
expansion of coal fired generation, especially in the near term.
What this suggests is that diversifying across technologies creates more optionality in
which technologies will be scalable in the future, as putting all the weight on a single
technology is very risky. While previously we advocated it was policy certainty that
encouraged investment in known technologies, here policy flexibility through
diversification is required to support investment in unknown technologies.
$46
$52
$57
$88
$124
$40
$57
$62
$69
$91
$92
$-
$20.00
$40.00
$60.00
$80.00
$100.00
$120.00
$140.00
Gas CCGT
@$4/MMBtu
Gas CCGT
@$5/MMBtu
Gas CCGT
@$6/MMBtu
PV - utility Solar thermal Wind Geothermal Advanced
Nuclear
Scrubbed coal
- PRB
Scrubbed coal
- APP
IGCC
LCOE-Generationcost($/MWh)
LCOE - Net after-tax capital cost ($/MWh) LCOE - Fixed O&M ($/MWh) LCOE - Variable O&M ($/MWh) LCOE - Fuel Cost ($/MWh)

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Box 3: The role of coal – Helping to alleviate energy poverty, though environmental
impact still a concern
Improving access to electricity is an important development goal. It is no coincidence that countries with low electricity
consumption are grouped at the bottom of the Human Development Index table. The causality between development
and electricity use goes in both directions: access to electricity impacts education (lighting at night for homework) and
health (replace indoor use of solid fuels for cooking and heating) as well as economic activity, while rising living
standards create the purchasing power for electric appliances.
According to the World Bank , 1.7 billion people have gained access to electricity supply in the past 20 years, taking the
global electrification rate to 83%, but more progress is needed; New York City (population: 8 million) consumes almost
as much electricity as Nigeria (164 million) and Bangladesh (153 million) combined. For these reasons, many
development agencies including the World Bank and the United Nations are focused on bringing electricity to the
remaining 1.2 billion people who still lack adequate access to electricity supply. Achieving this goal will lead to greater
demand for energy, including coal.
Exhibit 19: Significant gap in consumption per capita
Average electricity consumption per capita – MWh (2012)
Exhibit 20: India is heavily reliant on coal
Share of coal in power generation (2012)
Source: World Bank Source: McCloskey, Goldman Sachs Global Investment Research
Thermal coal is a cheap energy source that is widely available. Coal-fired plants are cheaper to build than nuclear
power, and with a few exceptions (e.g., shale gas in the United States) they have lower operating costs than gas-fired
plants. Provided that rail and port capacity is available to transport coal from the seaborne market to the plant,
commissioning new generation capacity is relatively straightforward. On these merits, and given the absence of
environmental regulation that could penalize coal-fired generation in energy-poor (EP) countries, we expect coal to play
an important role in addressing energy poverty. India is already a large consumer of coal, but other EP countries lag
well behind both in terms of overall consumption and as a share of the fuel mix. Existing and potential projects to build
new coal-fired plants in countries ranging from Pakistan to Myanmar will therefore bring electricity supply to millions of
people and boost demand for coal, albeit from a low base.
However, many of these regions are also amongst the most vulnerable to climate change and this will undoubtedly shift
future investment towards less polluting energy sources. Energy policies such as carbon pricing in China and lending
criteria from financing institutions such as the World Bank and the EBRD are likely to lead to a more diverse fuel mix in
some markets. India clearly has significant upside for thermal coal but the battle on energy poverty in other regions is
likely to have a more limited impact on coal demand.
0
2
4
6
8
10
12
14
US EU China World India other EP
0%
10%
20%
30%
40%
50%
60%
70%
India World EP - other Asia EP - Africa

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Five policy questions that need answers to kick-start the demand
phase of the revolution
We think the key to reducing uncertainty enough to kick-start the next “demand response”
phase of the “shale revolution” is the development of coherent and sustainable policies in
five key areas: best fracking practices and water rules, improving pipeline rules, capture of
fugitive methane, encouraging natural gas-based ethanol (E85) fueled and electric vehicles
in transportation sector and reforms to the power generation sector. These are the “low
hanging fruit” issues that we believe that framing well posed questions around could set
policy on the path to encouraging long-term confidence in the ability of the energy sector
to deliver its potential across North America.
What are best fracking practices and water rules?
We see four key issues related to drilling and completion of shale wells in which industry
and policymakers can further work together to promote transparency and environmental
stewardship. We highlight examples in which producers in some cases together with
policymakers have taken action.
 Disclosure of chemicals used in hydraulic fracturing. We believe it is key that there is
public confidence the environmental risks associated with the use of frac fluids are
acceptable. Hundreds of operators now disclose the components of chemicals on a
well-by-well basis on www.fracfocus.org.
 Reducing surface and air disturbance. In both rural and urban communities that have
seen increases in activity, there remain concerns regarding surface disturbance,
contribution from drilling/fracture stimulation on pollution/air quality and traffic/noise
that reduce quality of life for local residents. In 2008, the Bureau of Land Management
reached an agreement with producers in the Pinedale Anticline in Wyoming to allow
year-round drilling in a portion of the play but with more onerous restrictions on
surface disturbance, trucking and emissions.
 Ensuring well integrity to prevent groundwater contamination. We see a continued
need for industry to increase public confidence in well integrity to reduce concerns of
groundwater contamination. We view the casing of wells as key, particularly when
wells are being drilled through aquifers. We would note that EOG Resources indicated
that in 2012 it tested surface casing integrity and conducted annular pressure
monitoring of 100% of its operated wells.
 Measurement and recycling of water supply. Water disposal and water quality remain
an ongoing concern across shale plays, particularly in areas such as the Marcellus
Shale where there are limited to no options for drilling disposal wells. Producers such
as Cabot Oil & Gas and EQT in 2012 recycled almost all water that flows back from
completion. Nevertheless, there remains further opportunity to reduce freshwater
withdrawal used for drilling and completion. Before and after drilling, testing of
groundwater can help identify areas of non-compliance. Prior to drilling, Cabot gives
landowners the option to allow Cabot to test all water sources within 3,000’ of a
proposed well at company expense.
How can pipeline rules and regulations be improved?
Oil and natural gas pipelines have faced increasing siting and permitting challenges over
the last several years, which has sometimes slowed production and demand development,
including the switch to cleaner-burning natural gas. These delays can also increase costs
for the pipeline operator. We see three key areas for improvement in the process:
 Better federal-state-local coordination. Interstate pipelines must receive approval from
the Federal Energy Regulatory Commission (FERC) for new construction or

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modifications. However, many pipelines also require other federal and state permits,
which can often cause delays in construction and/or increase costs. FERC has the
ability to set deadlines for state permits, but lacks the authority to enforce these
deadlines. We recognize that new pipeline construction in particular will always require
state and local approval and must respect environmental, historical, or personal
property issues. However, we believe better adherence to permitting deadlines can
improve the pace and size of infrastructure investment and efficiency of the gas/oil
transportation network.
 Presidential permit. Pipelines which cross the US border require a “Presidential
Permit” whose jurisdiction falls under the Department of State. The well-documented
delays to the Keystone XL oil pipeline from Canada to the United States highlight the
challenges in this process – operator TransCanada originally filed its permit in the fall
of 2008, and has yet to receive a decision on its permit. We believe better coordination
between state and federal authorities, and increased clarity on the potential scope of
review as part of the National Interest Determination, would improve the process and
allow for more timely decision-making on projects that cross the border.
 Improved gas-electric coordination. A large portion of the growth in natural gas
demand over the last several years, and into the future, will come from power
generation. However, in many unregulated power markets such as New England,
merchant generators have little incentive to contract for firm capacity on new natural
gas pipelines as they do not have guaranteed recovery of those costs. We believe
mechanisms to encourage price signals to contract for gas pipeline capacity can
encourage increased investment in infrastructure.
What are optimal strategies for capturing fugitive methane?
Methane emissions have attracted increased attention in discussions around greenhouse
gases given methane is 20 times more efficient than carbon dioxide at trapping radiation in
the atmosphere. The EPA estimates methane accounted for about 9% of total GHG
emissions in 2012. We see three main areas where industry and policymakers can take
action to reduce methane emissions.
 Better measurement. The EPA estimates roughly 6.2 teragrams of methane emissions
in 2012 from the natural gas system, which equates to 323 billion cubic feet or around
1.3% of total production. However, other studies estimate methane emissions in the 3-
6% range from oil and gas production. A key measurement question involves the
“bottom-up” methodology from EPA, which measures emissions from individual
systems on the ground in a continuous manner, versus a “top-down” approach which
measures emissions via flights over producing regions on a one-off basis. Forthcoming
data-intensive bottom-up and top-down studies in producing regions, transmission
corridors and consumption areas should increase understanding of the true sources
and nature of methane emissions. Industry and policymakers should encourage
increased focus and investments on measurement tools and analysis to understand
the sources of methane emissions and means of capture – in other words, “measure it
to manage it.”
 Upstream – improve completion techniques. Based on our discussion, we believe
exploration and production companies could reduce methane emissions by using
larger-diameter pipe when completing natural gas wells. Welding more/larger pipe
makes for fewer connections and less leakage. Importantly, the upstream industry
should embrace these techniques, as they are potentially returns/profitability-
enhancing as they increase volumes/revenues, unlike midstream/downstream
operators where the commodity is a pass-through to customers.
 Midstream/downstream – accelerate/ improve integrity programs and financial
recovery. Most long-haul pipeline and local gas distribution companies have instituted
multi-year pipeline replacement programs to improve the safety and reliability of their

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infrastructure. This trend has accelerated in recent years due to some high profile
incidents, such as the explosion in San Bruno, California in 2010. We believe improving
the integrity of the system via pipeline replacement and monitoring has the ancillary
benefit of reducing methane emissions, since newer plastic pipelines at the distribution
level have a lower leakage rate, and increased monitoring at the large diameter
pipeline level can also reduce emissions. From a regulatory standpoint: (1) state
regulators could encourage increased investment in pipeline replacement programs,
and more “real-time” recovery of and on those capital investments, and (2) federal
regulators like the FERC could consider authorizing recovery of and on interstate
pipeline replacement and monitoring capital via annual automatic tariff increases,
similar to a recent ruling for the NiSource pipeline system, rather than a formal rate
case process.
How can natural gas-based ethanol (E85) fueled and electric vehicles be
encouraged in the transportation sector?
Today’s US light vehicle fleet is not positioned to consume large quantities of ethanol or
E85. OEMs do not allow new vehicles to run on fuel with more than 10% ethanol, due to
industry concerns over engine damage, particularly related to fuel lines and sealing
systems. In addition, while it is technically possible to convert existing cars’ gas engines to
run on E85, anti-tampering laws prevent this from happening in all but very few cases. We
offer 2 specific policy recommendations to support natural gas based ethanol demand and
one to support Electric vehicle demand:
 Mandate, or further incentivize flex fuel vehicles: Because the technology has already
been developed and fully tested in the US, manufacturers can significantly increase its
installation and usage rates at negligible additional cost. More consistent use of flex
fuel technology will put the industry in a better position to evolve its usage of other
alternative fuels. Another area of policy support could be subsidizing the expense of
converting some of the nation’s 121,000 gas stations to offer ethanol, which comes at a
cost of $300,000 per island on some estimates.
 Make the Renewable Fuel Standard more flexible: Even with more E85 vehicles it will
take time to change the characteristics of the vehicle fleet and generating near-term
demand of natural gas based ethanol we would likely require some flexibility from the
Renewable Fuel Standard to allow it to be used along with renewable based ethanol.
This is because given the “blend wall” of 10% for most vehicles we are already not
consuming the 15bn gallons of renewable ethanol targeted by the RFS.
 For EVs, policy can step in to shorten the payback period: While the returns on an EV
investment are economically sensible at a 17% ROIC, this translates into a payback of
six years, which is a bit on the long side for most car buyers. This payback should come
down over time as scale and competition ramp up, but in the interim the government
could provide capital to fund the estimated incremental cost of $8,330 for an EV
(keeping the buyer’s monthly payments similar to a conventional ICE) and then recoup
this by taking a portion of the annual savings through taxes (as EVs cost much less to
operate than gas cars). This would still leave the consumer with lower net
transportation costs, and have a clear GHG benefit.
What reforms in the power generation sector should be instituted?
The US power sector, given lengthy investment timeframes, needs more certainty from
various regulators, policy makers and stakeholders. Multiple policy making bodies
significantly impact the long-term design and structure of US power generation. Federal
utility regulators and regional grid operators play a key role in designing and monitoring
competitive regional power markets, while state utility regulators still oversee, in certain
areas, the changing shape of power generation. Environmental agencies, federal and state,
shape the rules and regulations that impact what types of generation may need

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incremental controls or face cost challenges. Congress and the Administration remain key –
given their role in the development and growth of emerging technologies, such as
renewables, energy efficiency, nuclear and even coal technologies, through tax and other
related incentives that stimulate investment.
 Revising market designs and structures in several competitive power markets that will
encourage use of long-term contracts – to provide more certainty for developers and
owners of power plants – and to lower costs, especially for financing. Multiple US
regional competitive power markets, including the major ones in the East, MidAtlantic
and parts of the Midwest, maintain designs that hinder the use of long-term contracting
for new plants or even for existing ones. This should change, via coordinated actions
by state and federal power or utility sector regulators and stakeholders, to adopt market
structures that enable generators to enter multi-year deals in these markets.
 Providing long-term certainty on economic incentives and mandates for potential new
renewable, clean coal and nuclear power plants. Over the last 10-12 years, the US
created tax incentives and state mandates that drove significant development of new
renewables – but we note every few years, these incentives expire, creating a
“boom/bust” cycle for renewable development, until Congress passes a new short-term
extension, like the one that exists through 2015 now for federal renewable tax credits.
We need multi-year certainty – given the lengthy time horizon needed to site, develop
and build new plants – not just renewables, but also emerging clean coal or even
nuclear ones.
 Regulatory visibility for environmental rules – at the state and federal levels – will
enable power companies to plan for future changes in their generation mix. Multiple
rules, both state and federal, continue to emerge that will impact clean air and clean
water requirements from existing and potential new power plants. Increased certainty
regarding the timeline and implementation of these rules – as well as increased
coordination across federal and state regulators – would enable power companies
operating in multiple states to design and implement generation changes that could
serve entire regions – but they need further detail on state and federal requirements
before they can fully plan their generation portfolios.
Over the last 10-15 years, the United States witnessed a significant growth in renewables,
triggered by state portfolio standards and federal/state incentives. While continued
renewable growth will come, due to their intermittency issues there will be an increasing
need for fast-starting gas-fired generating units that can ramp quickly when renewables go
offline. Legislation to stimulate renewables, clean coal or even nuclear technologies via tax
or other incentives tends to have short time horizons, creating significant investment
uncertainty every few years after legislation passes. Efforts to stimulate emerging
technologies need multi-year provisions to create longer cycles (critical especially for
renewables such as wind) and also therefore impacting gas plant development that should
“back-stop” additional renewables.

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Policy focus 1: Reducing uncertainty to encourage sustained
industrial development
How significant could shale gas be for US chemical production?
According to data from the American Chemistry Council, there are currently more than 100
new US chemical projects valued at $96bn scheduled to take advantage of low-cost US
shale with more than half (55%) of these projects proposed by non-US companies.
Most of these projects are being built with exports of finished products in mind, which
could help improve the US trade deficit. The American Chemistry Council expects the
chemical trade surplus to escalate from $800mn in 2012 to nearly $30bn in 2018 with
market share gains from other key developed market production centers such as Europe
and Japan. Almost all of the growth in the trade surplus would come from basic chemicals
(petrochemicals) whose export surplus is expected to grow $25bn over that time period.
This wave of investment could provide more than 500,000 construction and capital goods
manufacturing jobs through 2020 to execute all this construction. For context, the US
chemical industry currently employs just under 800,000 people. Additionally, these are
some of the best-paying jobs in manufacturing with average hourly wages over $20/hour.
We believe extending the current investment excitement beyond the near-term requires
increased confidence in future energy prices and supplies. Should US manufacturers
become comfortable that current relative cost curves can be sustained, even after the
current wave of expansion is absorbed, we would expect a second reinvestment wave, and
all its attendant domestic benefits, to occur.
As a theoretical question, it is interesting to explore just how much global market share US
producers could take through low-cost capacity additions. We attempt to answer this
question for three of the largest commodity chemicals – ethylene, chlorine/caustic, and
methanol – to get a sense of the upper-end of the theoretical bounds of harnessing shale.
For these three products alone, over $350bn of capital spending (2013 US dollar terms)
in the United States would be needed to fully take market share from disadvantaged
regions. Furthermore, from that point another $20bn of capital spending per year would be
needed to build capacity to supply 100% of global demand growth for these three products.
These figures dwarf the already-announced investments depicted in Exhibit 21, but are
unlikely to be fully realized for a number of reasons, which we discuss below.

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US capacity, which is advantaged by shale gas, currently accounts for 19% of global
production. Another 30% of global production (mostly Middle East) is cost advantaged,
similar to the United States. This leaves around 50% of global production susceptible to US
market share gains, as shown in the global cost curve in Exhibit 24.
Exhibit 24: Global ethylene cost curve
Ethylene breakeven costs by region/feedstock (2013), in US $/tonne
Source: IHS Chemical
Because natural gas and NGL production growth in other cost-advantaged regions (e.g.,
the Middle East) is limited, there is little competitive threat from new supply from these
regions. This provides US producers with an opportunity to add capacity to meet the
world’s growing demand as well as to take market share from high-cost regions such as
Europe and Asia.
We forecast global ethylene demand to grow around 11bn pounds per year, which is 19%
of the current US installed capacity of 57bn pounds. In other words, the United States
could increase its ethylene capacity nearly 20% each year just to supply global demand
growth without displacing overseas production.
Taking this exercise to its theoretical limit, the United States could also displace the
existing 146bn pounds of disadvantaged global production. This would require nearly
quadrupling the US ethylene industry from 57bn pounds to 203bn pounds. While this
is highly unlikely for a number of reasons, we believe that is shows the vast potential for
further ethylene projects.
We estimate the current capital expenditure for ethylene at roughly $1.00 of capex per
pound of capacity. Capital spending for necessary derivative capacity is currently another
$0.75 per pound. We would also expect significant cost inflation as multiple projects
compete for limited materials and labor, made worse by the US restrictions on work visas.
As a result, the current $1.75 per pound capital cost could easily grow to $2.00 per pound in
coming years.
0
200
400
600
800
1000
1200
1400
Middle East
Ethane
US Ethane China (Coal
based)
SEA Naphtha US Naphtha EU Naphtha NEA Naphtha

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Using a $2.00 per pound capital cost estimate on the potential 146bn pounds of new
capacity to fully exploit the cost advantage would imply a further $292bn of capital
investment in the US for ethylene alone. Additionally, if US producers were to try to
capture all of the global demand growth, that would necessitate a further $22bn per year of
investment into perpetuity.
Chlorine/Caustic
The electrolysis of brine (salt water) to produce chlorine and the by-product caustic soda is
referred to as chlor-alkali production. For every ton of chlorine produced, 1.1 tons of caustic
soda are made as a by-product. This combination of chlorine and caustic is referred to as
an Electrochemical Unit (ECU).
The global chlor-alkali market is 66mn tons growing in line with global GDP growth. US
capacity, which is advantaged by shale gas, is 15mn tons or 23% of global demand. There
is limited other advantaged capacity globally and we estimate 70% of global capacity is
higher-cost than US capacity.
Applying the same theoretical exercise as we did with ethylene, US capacity could
quadruple from 15mn tons today to 60mn tons to fully capture this disadvantaged
capacity. Similar to ethylene, there are a number of reasons why this is impractical, but it
still illuminates the potential opportunity.
We estimate the current capital expenditure for chlor-alkali at $1,150 per ton of capacity.
Using this as a benchmark would imply over $50bn of capital investment in the
United States for chlor-alkali alone. We would also likely expect further investment
downstream of chlorine into the vinyls chain (EDC/VCM/PVC) in order transform chlorine
into an exportable form. This downstream investment could double the $50bn initial chlor-
alkali capital spending.
Methanol
Methanol is a 66mn ton global market growing 2x-3x global GDP growth. Much of the
global growth is being driven by China, where numerous projects are underway to turn
local coal into methanol for use as transportation fuel or as a feedstock for ethylene (and
other chemicals) production.
As we discussed above, the US methanol industry was badly damaged in the 2000-2010
period due to record high natural gas prices and lackluster domestic demand. As a result,
only 4% of global capacity is in the United States today. We estimate another 72% of global
production is cost-advantaged, including stranded-gas locations in the Caribbean and coal-
gasification projects in China.
This still leaves roughly 25% of global production as at-risk for market share gains from the
United States. Furthermore, the faster growth rate for methanol demand (vs. other
commodity chemicals) provides more opportunity for US capacity additions. Therefore,
the United States could theoretically grow its methanol capacity 500% from 3mn tons
to 19mn tons to capture 25% more market share. From there it could add 5mn tons per
year more capacity to capture all of the global demand growth. Again, we view this as
impractical for a number of reasons, but it illustrates the opportunity.
We estimate the current capital expenditure for methanol at $900 per ton of capacity. Using
this as a benchmark would imply $14bn of capital investment in the United States for
methanol to take share from disadvantaged regions. It would also imply over $4bn
per year in capital expenditure to capture 100% of global demand growth. Further
downstream capital expenditures would be likely, but would be of smaller size.

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The upside can be exploited with policy clarity
Given the competitive advantage the United States now enjoys across a wide array of
energy-intensive manufacturing sectors, the size of the potential opportunity to kick-start a
North American manufacturing renaissance is demonstrably large. However, this
impressive potential compares against a rather lackluster base case projection for
industrial demand as published by the EIA in its 2014 Annual Economic Outlook (see
Exhibit 25). The key to this divergence between the potential and the projection is the
policy environment.
Exhibit 25: The potential upside is meaningful, but policy is needed to make it reality
GS estimated maximum potential industrial gas demand vs. base case (EIA growth projections
through 2040, extrapolated beyond), Bcf/d
Source: EIA, Goldman Sachs Global Investment Research.
To access the potential that North America has to exploit its cost advantage and increase
market share, several current uncertainties need to be addressed to give business the
confidence that the current competitive advantage is sustainable.
Given the long-term, irreversible nature of these investments, management make
investment decisions based on a 20-30 year view of profitability rather than just current
margins. With questions currently raised over the future evolution of policies to address
fracking and wholesale exports of US LNG, the clarity over natural gas prices and
availability of supplies which is necessary to encourage investment is clearly not yet in
place. Until these issues are addressed, the chemicals industry will likely begin to face the
same challenges that US refining now faces, where uncertainty over the export ban has
paralyzed investment.
Further, while it is currently not practical to hedge margins out on a long-term basis, which
itself may discourage investment, we view the underlying logic here as somewhat circular.
Policy changes which encourage business confidence and encourage investment would
likely materially increase market liquidity for longer-term hedging, further reducing
-
10.00
20.00
30.00
40.00
50.00
60.00
70.00
2001 2005 2009 2013 2017 2021 2025 2029 2033 2037 2041 2045 2049
`Max. potential' case `Base' case

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uncertainty. Therefore, we see policy as capable of kick-starting a virtuous cycle of reduced
uncertainty and increased ability to hedge longer term risks.
Clarity over price is not the only thing that matters before business can be confident of
sustainably embarking on a new revolution in manufacturing. Importantly, clear
environmental policy that anticipates this potential change must be laid out to present a
clear vision of the future. For instance, air quality rules and carbon capture policies could
be managed to actively develop the vision of a sustainable North American manufacturing
renaissance.
Finally, as we highlighted above, uncertainty still exists over immigration policy that is
needed to attract the skilled labor in the near term to fill the plants and help to grow the
industry.
We believe that these uncertainties can all be managed effectively through a coordinated
effort between business leaders and policymakers. We believe that there is material upside
to ensure that the announced $96bn of project spending currently forecasted by the
American Chemistry Council does not stop there, but continues to flourish into a full
renaissance in North American energy intensive manufacturing.

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Exhibit 27: The US transportation fuel landscape is far from established; we explore three probable scenarios
Current and projected fleet powertrain mix under various scenarios
Source: Goldman Sachs Global Investment Research.
With natural gas-based ethanol and EVs looking like the most promising alternatives to
traditional gasoline, we outline two potential upside scenarios which we believe reflect
realistic adoption rates of these powertrains under appropriate policy support and contrast
against a “status quo” scenario involving no significant change in the policy landscape
(see Exhibit 27). We note that in all cases the characteristics of the fleet would change
very gradually given the long replacement cycle for vehicles (which can last 20 years),
and long powertrain product cycles of 7-10 years. So that even if EVs were an easy
choice today, the earliest sales of 100% EV would be in 2024, and changing the mix of
250mn vehicles on the road would take even longer. As such our projections look out to
2050, a timeframe over which larger fleet changes can happen.
Summary of three scenarios
1. We have policy support for natural gas. As we argue in more detail below, the
economic rationale for using natural gas-based ethanol already exists given a relatively
low payback of two years. But in this upside case policy tips the balance in a multitude
of possible ways: (1) mandating flex fuel vehicles, (2) supporting investment for drilling
and refining, or (3) improving the already-attractive payback though tax subsidies
relative to gasoline, on the grounds of the lower cost to the consumer and possibly
lower well-to-wheel emissions under an ethanol-fueled autos market, as we discuss in
greater detail below. Under these supportive conditions we could see ethanol (E85)
powertrains making up 40% of the fleet 2050 from 2% today. This would imply peak
light vehicle natural gas demand of 6.6 Tcf, equivalent to approximately 30% of today’s
production.
2. EVs gain traction. In this scenario, electric vehicles become the technology that wins
out over gasoline. EVs already have a meaningful efficiency advantage over ICEs, with
the main drawback being the upfront investment cost. Here we assume the catalyst for
accelerated adoption is more of a reduction in cost than policy, though government
could potentially continue to play a role in subsidizing the cost of ownership such as
extending the Federal buyers tax credit to accommodate higher volumes. Moreover,
EV investments currently have a positive present value, such that lower marginal
electricity costs ultimately justify the cost of the vehicle. However, consumer payback
horizons are usually relatively short-term in the autos industry, meaning that the
Scenario ‐ Policy Supports Natural Gas 2014 2050 Scenario ‐ EV Technology Improvement 2014 2050 Scenario ‐ Status Quo 2014 2050
Gasoline ICE 95.6% 41.4% Gasoline ICE 95.8% 46.1% Gasoline ICE 95.8% 67.8%
Electric Vehicles 2.0% 14.2% Electric Vehicles 1.9% 40.3% Electric Vehicles 1.9% 15.0%
M85 ICE 0.0% 0.0% M85 ICE 0.0% 0.0% M85 ICE 0.0% 0.0%
E85 ICE 2.1% 39.9% E85 ICE 2.1% 9.1% E85 ICE 2.1% 7.6%
CNG Powered ICE 0.2% 4.5% CNG Powered ICE 0.2% 4.4% CNG Powered ICE 0.2% 9.5%
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
Renewable Fuel Standard (bn gallons) 14.4 15.0 Renewable Fuel Standard (bn gallons) 14.4 15.0 Renewable Fuel Standard (bn gallons) 14.4 30.0
2014 2014 2014 205020502050
Gasoline ICE Electric Vehicles M85 ICE
E85 ICE CNG Powered ICE
Gasoline ICE Electric Vehicles M85 ICE
E85 ICE CNG Powered ICE
Gasoline ICE Electric Vehicles M85 ICE
E85 ICE CNG Powered ICE